Field of the Disclosure
The present disclosure generally relates to use of a downhole isolation valve to sense annulus pressure.
Description of the Related Art
A wellbore is formed to access hydrocarbon bearing formations, e.g. crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill string. To drill the wellbore, the drill string is rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling a first segment of the wellbore, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.
An isolation valve assembled as part of the casing string may be used to temporarily isolate a formation pressure below the isolation valve such that a drill or work string may be quickly and safely inserted into or removed from a portion of the wellbore above the isolation valve that is temporarily relieved to atmospheric pressure. Since the pressure above the isolation valve is relieved, the drill/work string can be tripped into the wellbore without wellbore pressure acting to push the string out and tripped out of the wellbore without concern for swabbing the exposed formation.
Once the first segment has been cased, the drill string may be redeployed into the wellbore to drill through the formation. During drilling through the formation, the well is controlled by maintaining a bottomhole pressure (BHP) greater than or equal to a pore pressure of the formation. If the BHP is allowed to decrease below the pore pressure, formation fluid will enter the wellbore. If the BHP exceeds fracture pressure of the formation, the formation will fracture and wellbore fluids may enter the formation. Conventionally, the BHP is estimated using standpipe and wellhead pressures measured at surface.
The influx of formation fluids into the wellbore is referred to as a kick. Kicks may occur for reasons, such as drilling through an abnormally high pressure formation, creating a swabbing effect when pulling the drill string out of the well for changing a bit, not replacing the drilling fluid displaced by the drill string when pulling the drill string out of the hole, and fluid loss into the formation resulting from overpressure thereof. A kick may be detected by drilling fluids flowing up through the annulus after pumping is stopped or by a sudden increase of the fluid level in the drilling fluid pit/tank. Because the formation fluid entering the wellbore ordinarily has a lower density than the drilling fluid, a kick will potentially reduce the hydrostatic pressure within the well and allow an accelerating influx of formation fluid. If not properly controlled, the kick may lead to a blowout which may result in the loss of the well, the drilling rig, and possibly the lives of those operating the rig.